Hydrocarbons, such as oil, may be recovered from hydrocarbon containing formations (or reservoirs) by penetrating the formation with one or more wells, which may allow the hydrocarbons to flow to the surface. A hydrocarbon containing formation may have a natural energy source (e.g. gas, water) to aid in mobilizing hydrocarbons to the surface of the wells. For example, water or gas may be present in the formation at sufficient levels to exert pressure on the hydrocarbons to mobilize them to the surface of the production wells. However, reservoir conditions (e.g. permeability, hydrocarbon concentration, porosity, temperature, pressure) can significantly impact on the economic viability of hydrocarbon production from any particular hydrocarbon containing formation. Furthermore, any natural energy sources that exist may become depleted over time, often long before the majority of hydrocarbons have been extracted from the reservoir. Therefore, supplemental recovery processes may be required and used to continue the recovery of hydrocarbons from the hydrocarbon containing formation. Examples of known supplemental processes include waterflooding, polymer flooding, alkali flooding, thermal processes, solution flooding or combinations thereof.
In recent years there has been increased activity in developing new and improved methods of chemical Enhanced Oil Recovery (cEOR) for maximising the yield of hydrocarbons from a subterranean reservoir. In surfactant EOR the mobilization of residual oil saturation is achieved through surfactants which generate a sufficiently (ultra) low crude oil/water interfacial tension (IFT) to give a capillary number large enough to overcome capillary forces and allow the oil to flow (Chatzis & Morrows, “Correlation of capillary number relationship for sandstone”, SPE Journal, vol. 29, p. 555-562, 1989). However, different reservoirs can have very different characteristics (e.g. crude oil type, temperature, water composition—salinity, hardness etc.), and therefore, it is desirable that the structures and properties of the added surfactant(s) be matched to the particular conditions of a reservoir to achieve the required low IFT. In addition, a promising surfactant must fulfil other important criteria such as low rock retention or adsorption, compatibility with polymer, thermal and hydrolytic stability and acceptable cost (including ease of commercial scale manufacture).
Compositions and methods for EOR are described in U.S. Pat. Nos. 3,943,160, 3,946,812, 4,077,471, 4,216,079, 5,318,709, 5,723,423, 6,022,834, 6,269,881 and “Low Surfactant Concentration Enhanced Waterflooding”, Wellington et al., Society of Petroleum Engineers, 1995.
Compositions and methods for EOR utilizing internal olefin sulfonates (IOSs) are known, e.g. from U.S. Pat. No. 4,597,879. The compositions described in the foregoing patent have the disadvantages that both brine solubility and divalent ion tolerance are insufficient under certain reservoir conditions. U.S. Pat. No. 4,979,564 describes the use of IOSs in a method for EOR using low tension viscous waterflood. An example of a commercially available material described as being useful was ENORDET® IOS 1720, a product of Shell Oil Company identified as a sulfonated C17-20 internal olefin sodium salt. This material has a low degree of branching. U.S. Pat. No. 5,068,043 describes a petroleum acid soap-containing surfactant system for waterflooding wherein a cosurfactant comprising a C17-20 or a C20-24 IOS was used. In “Field Test of Cosurfactant-enhanced Alkaline Flooding” by Falls et al., Society of Petroleum Engineers Reservoir Engineering, 1994, the authors describe the use of a C17-20 or a C20-24 IOS in a waterflooding composition with an alcohol alkoxylate surfactant to keep the composition as a single phase at ambient temperature without significantly affecting performance at reservoir temperature. The water had a salinity of about 0.4 wt. % of sodium chloride.
There is also industry experience with the use of certain alcohol alkoxysulfate surfactants in EOR. However, these materials, used individually, also have disadvantages under relatively severe conditions of salinity, hardness and temperature, in part because certain alcohol alkoxysulfate surfactants are not stable at high temperature, i.e. above 70° C. For example, WO2004081342 discloses the use in EOR of a “Neodol® C16-C17 branched sulfate”, which is an aliphatic anionic surfactant, in combination with an aliphatic nonionic additive.
Generally, solvents, such as sec-butanol, isopropanol, tert-amyl alcohol and others, also referred to as “co-solvents”, are added to hydrocarbon recovery compositions in order to improve the water solubility of the surfactants under the conditions at the surface and to reduce the viscosity of the fluid under the surface. Co-solvent in alkali-surfactant-polymer or surfactant-polymer hydrocarbon recovery formulations is used to aid aqueous solubility and to improve interaction with crude oil thereby preventing the formation of highly viscous phases.
However, adding such co-solvent may also lower the solubilization ratio at optimal salinity. Thus, generally, a compromise must be made between maximum solubilization ratio (low IFT) and low viscosity and the other critical factors needed for good transport under low pressure gradients in oil reservoirs. An additional disadvantage is the associated cost of the requirement to add a co-solvent.
A hydrocarbon recovery composition comprising ammonium C16-17 7PO sulfate and sodium C15-18 internal olefin sulfonate is disclosed by Liu et al. in “Favorable Attributes of Alkaline-Surfactant-Polymer Flooding”, SPE Journal, March 2008, p. 5-16. It is disclosed that mixtures of said two surfactants can be injected as a single-phase micellar solution of relatively low viscosity at ambient temperature at salinities approaching or in some cases even exceeding optimal salinity for many oils without addition of alcohol or oil. The above-mentioned viscosity relates to the injectible fluid and not to micro-emulsion viscosity.
Injection of a single-phase solution is important because formation of precipitate, liquid crystal or a second liquid phase can lead to non-uniform distribution of injected material and non-uniform transport owing to phase trapping or different mobilities of coexisting phases.
Further, it is described by Levitt et al. in “Identification and Evaluation of High Performance EOR Surfactants”, SPE 100089, 2006, p. 1-11, that the most promising formulation for application in the reservoir in question was a mixture of C16-17—(PO)7—SO4, C15-18 internal olefin sulfonate and sec-butanol (“PO” stands for “propylene oxy”). It is disclosed that at 1 wt. % surfactant concentration and 2 wt. % sec-butanol, this formulation equilibrates rapidly and exhibits a high solubilization ratio at optimal conditions. Thus, in this case, the weight ratio of total surfactant to co-solvent was 1:2.
It is desirable that no or substantially less co-solvent may be used in hydrocarbon recovery formulations and that at the same time an effective EOR performance of such formulations is still maintained. Using no or substantially less co-solvent is very important because co-solvent is a major chemical component of a surfactant EOR operation in terms of cost and complexity.